U.S. patent application number 10/398927 was filed with the patent office on 2003-11-27 for methods and apparatus for separating fluids.
Invention is credited to Mohsen, Abdul Hameed, Nashat, Mohammed, Shaheen, Mansour, Tengirsek, Alp, Wilson, Thomas.
Application Number | 20030217956 10/398927 |
Document ID | / |
Family ID | 22904535 |
Filed Date | 2003-11-27 |
United States Patent
Application |
20030217956 |
Kind Code |
A1 |
Mohsen, Abdul Hameed ; et
al. |
November 27, 2003 |
Methods and apparatus for separating fluids
Abstract
Methods of treatment of fluids produced by an oil or gas well
following a stimulation operation, allowing separation from the
fluids and re-injection of oil and gas hydrocarbons in a production
pipeline under pressure, and allowing achievement of suitable
quality for the residual fluids compatible with their rejection,
for example into the sea, including the following three elements;
neutralization of the fluids by mixing with a high pH chemical,
until the resulting pH reaches a level compatible with the
equipment and pipes; use of optimized emulsion breakers in a phase
separator, selected for best results with the fluids produced by
the well, to accelerate the separation of oil from the fluids, and
to lower the residual oil content in the fluids to levels
compatible with environmental regulations; and use of a multi-phase
pump to pump the oil and gas hydrocarbons produced and reinject
them in a pipeline under pressure.
Inventors: |
Mohsen, Abdul Hameed;
(Abu-Dhabi, AE) ; Nashat, Mohammed; (Al-Mutlaq
Compound, SA) ; Shaheen, Mansour; (Cairo, EG)
; Tengirsek, Alp; (Lumpur, MY) ; Wilson,
Thomas; (Tanager, NO) |
Correspondence
Address: |
SCHLUMBERGER OILFIELD SERVICES
200 GILLINGHAM LANE
MD 200-9
SUGAR LAND
TX
77478
US
|
Family ID: |
22904535 |
Appl. No.: |
10/398927 |
Filed: |
July 7, 2003 |
PCT Filed: |
October 10, 2001 |
PCT NO: |
PCT/EP01/11712 |
Current U.S.
Class: |
210/188 ;
166/267; 95/153; 95/253; 96/182 |
Current CPC
Class: |
E21B 43/34 20130101;
B01D 17/0208 20130101; B01D 17/0217 20130101; B01D 19/0068
20130101; B01D 17/047 20130101; B01D 17/00 20130101 |
Class at
Publication: |
210/188 ; 95/153;
95/253; 96/182; 166/267 |
International
Class: |
B01D 019/00 |
Claims
1 A method of separating multiphase fluids produced from a well,
comprising: (i) feeding the multiphase fluids to a separator so as
to form separate water and hydrocarbon phases; (ii) injecting, via
multiphase testing equipment, at least part of the hydrocarbon
phase into a production pipeline; and (iii) discharging the water
phase.
2 A method as claimed in claim 1, wherein injection of the
hydrocarbon phases into die production pipeline takes place via a
multiphase pump.
3 A method as claimed in any of claims 1 or 2, wherein the
hydrocarbon phase comprises a gas phase and an oil phase, the
method further comprising the steps of (i) separating the oil and
gas phases; and (ii) injecting the oil phase into the production
pipeline.
4 A method as claimed in claim 3, further comprising burning the
gas phase.
5 A method as claimed in claim 3, comprising injecting the gas and
oil phases into the production pipeline.
6 A method as claimed in any preceding claim, further comprising
treating the water phase to further reduce its oil content in the
water phase
7 A method as claimed in claim 6, comprising reducing the oil
content in the water phase to less than 80 ppm.
8 A method as claimed in claim 6 or 7, wherein the step of reducing
the oil content in the water phase is using a skimmer.
9 A method as claimed in any of claims 6, 7 or 8, further
comprising using selected chemicals to accelerate breaking of
emulsions.
10 A method as claimed in claim 9, wherein the chemicals comprise
surfactants including methanol-based cationic and anionic surface
active agents, naphtha-based non-ionic surfactants, water-based
surfactants, dodecylbenzene sulfonic acid-based non-ionic
surfactants, propan-2-ol based surfactants, or blends thereof.
11 A method as claimed in claim 10, wherein the methanol-based
cationic and anionic surface active agents comprise:
10 quaternary amine compounds 15-40% methanol 30-60% aromatic
alcohol glycol ether 7-13% propan-2-ol 3-7%.
12 A method as claimed in claim 10, wherein the naphtha-based
non-ionic surfactants comprise:
11 naphthalene 5-10% poly(oxy-1,2-ethanediyl)-n- onylphenyl-hydroxy
1-5% heavy aromatic naphtha 60-100%.
13 A method as claimed in claim 10, wherein the water based
surfactants comprise:
12 propan-2-ol 30-60% aliphatic alcohol glycol ether 10-30%
methanol 5% water 30-60% oxyalkylated alkanols 0-20% quaternary
amine iodide derivatives 0-1% quaternary amine chloride derivatives
0.1-1%
14 A method as claimed in claim 10, wherein the dodecylbenzene
sulfonic acid-based non-ionic surfactants comprise:
13 dodecylbenzene sulfonic acid 54%
poly(oxy-1,2-ethanediyl)-nonylphenyl-hydroxy 10-30% methanol
24%.
15 A method as claimed in claim 10, wherein the dodecylbenzene
sulfonic acid-based non-ionic surfactants comprise:
14 dodecylbenzene sulfonic acid 30-60%% propan-2-ol 10-30% glycol
3-7% water 1-5% 1.sup.st glycol-ether 7-13% 2.sup.nd glycol-ether
10-30%.
16 A method as claimed in claim 10, wherein the propan-2-ol based
surfactant comprises:
15 propan-2-ol 15-40% aromatic hydrocarbon 5-10% oxyalkylated
polyol 10-30% alkyl ether phosphate ester 5-10% 1.sup.st
oxyalkylated alkanols 5-10% 2.sup.nd oxyalkylated alkanols 5-10%
resin 7-13% water 7-13%.
17 A method as ,claimed in claim 10, wherein the water-based
surfactants comprise:
16 1.sup.st polyglycol ether 15-25% 2.sup.nd polyglycol ether
10-30% propan-2-ol 15-25% 2-butoxyethanol 17-25% water 10-30%.
18 A method as claimed in any of claims 10-17, wherein the
surfactant blend comprises:
17 methanol-based cationic and anionic surface active agents 40%
naphtha-based non-ionic surfactants 30% water-based surfactants
30%.
19 A method as claimed in any of claims 10-17 , wherein the
surfactant blend comprises:
18 naphtha-based non-ionic surfactants 30% dodecylbenzene sulfonic
acid-based non-ionic surfactants 30% water-based surfactants
20%.
20 A method as claimed in any preceding claim, further comprising
treating any clean up fluids present in the fluids produced from
the well.
21 A method as claimed in claim 20, wherein the step of treating
the clean up fluids can comprise neutralizing any acid in the
fluids.
22 A method as claimed in claim 21, comprising neutralizing acid
using a solution of Na.sub.2CO.sub.3.
23 A method as claimed in claim 22, wherein the solution is
injected into the fluids prior to their passing to a separator. The
first idea was
24 A method as claimed in claim 23, comprising raising the pH of
the fluids to at least 5.5 prior to injection into the
separator.
25 A method as claimed in any preceding claim, comprising: (i)
feeding the fluids to a separator to form a water phase and an oil
phase; (ii) passing the water phase to a skimmer in which any oil
contained in the water phase is allowed to separate flier; (iii)
passing the oil phase to a surge tank in which any water contained
in the oil is allowed to separate further; (iv) passing separated
oil from the skimmer to the surge tank; (v) passing separated water
from the surge tank to the skimmer; (vi) injecting oil from the
surge tank into a production pipeline and (vii) discharging water
from the skimmer.
Description
FIELD OF THE INVENTION
[0001] The present invention relates to the separation and testing
of fluids obtained from underground formations. In particular, the
invention provides new techniques for the separation of fluids from
subterranean hydrocarbon wells, which are especially applicable in
offshore situations.
BACKGROUND
[0002] The invention provides new solutions to address certain
major environmental problems typically encountered in hydrocarbon
exploration and production wells, especially in offshore
operations. A common practice in certain regions (for example the
Middle East) is to stimulate drain holes in carbonate reservoirs
with hydrochloric acid, and then clean up the well before
connecting it to the production line. One previous approach has
been to direct clean up fluids through a burner until the pH falls
to less than 6, burning all hydrocarbons produced and dumping the
spent acid and contaminated mud in the sea Burning has an
environmental and economical impact. The hydrocarbon burning
produces toxic gases, soot, acid rain, unburned hydrocarbons and a
large amount of CO.sub.2, all of which are detrimental to the
environment.
[0003] The direct economic impact is the cost of the oil and gas
lost in flaring as well as the cost of burning equipment. This
equipment has a large footprint (physical size), cost, power
consumption and noise. Moreover, the risk of acid corrosion of
pipelines under the sea is high. Any pipeline leak resulting from
corrosion can potentially cause a shut down of production for
several weeks as well as high repair costs and major pollution.
Indirect costs linked to the large liability exposure due to the
potential and actual damage to the environment are difficult to
evaluate but could be several order of magnitude larger than direct
costs.
[0004] In addition to acid and mud, well fluids, often containing
oil at a concentration of about 3000 ppm, are also often dumped
into the sea One aim of the present invention is to provide
techniques to help reduce the oil content of water from a typical
3000 ppm to 10-80 ppm during a well test operation.
SUMMARY OF THE INVENTION
[0005] The invention provides methods of separating multiphase
fluids produced from a well, comprising: feeding the multiphase
fluids to a separator so as to form separate water and hydrocarbon
phases; injecting at least part of the hydrocarbon phase into a
production pipeline; and discharging the water phase.
[0006] Preferably, injection of the hydrocarbon phases into the
production pipeline takes place via multiphase testing equipment
and a multiphase pump.
[0007] Where the hydrocarbon phase comprises a gas phase and an oil
phase, the method can include the step of separating the oil and
gas phases, injecting the oil phase into the production pipeline
and, optionally, burning the gas. Alternatively, the gas and oil
phases are both injected into the production pipeline, in which
case flaring of the gas phase can be avoided.
[0008] The method can also include the step of treating clean up
fluids present in the fluids produced from the well and reducing
the oil content in the water phase (e.g. to less than 80 ppm). The
step of treating the clean up fluids can comprise neutralizing any
acid in the fluids. Separation of the oil and water phases are
effected using a skimmer and, optionally, selected chemicals to
accelerate breaking of emulsions.
[0009] The invention provides a method of treatment of fluids
produced by an oil or gas well following a stimulation operation,
allowing separation from the fluids and re-injection of oil and gas
hydrocarbons in a production pipeline under pressure, and allowing
achievement of suitable quality for the residual fluids compatible
with their rejection, for example into the sea, characterized by
the combination of the following three elements:
[0010] 1. Neutralization of the fluids by mixing with a high pH
chemical, until the resulting pH reaches a level compatible with
the equipment and pipes;
[0011] 2. Use of optimized emulsion breakers in a phase separator,
selected for best results with the fluids produced by the well, to
accelerate the separation of oil from the fluids, and to lower the
residual oil content in the fluids to levels compatible with
environmental regulations; and
[0012] 3. Use of a multi-phase pump to pump the oil and gas
hydrocarbons produced and re-inject them in a pipeline under
pressure.
[0013] This method can be further characterized by the use of a
soda ash solution (Na.sub.2CO.sub.3) to neutralize the fluids
produced by the well after a stimulation treatment using
hydrochloric acid (HCl), and characterized by a pH of at least 5.5
for the neutralized fluids before injection in the separator
equipment.
[0014] A blended surfactant demulsifier can be used to maximize the
efficiency of the separation of oil from the fluids. The use of a
non-toxic demulsifier for the separation of oil from the fluids is
preferred.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] FIG. 1 shows a schematic of a system according to one
embodiment of the invention;
[0016] FIG. 2 shows a plot of soda ash volume vs. spent acid
volume;
[0017] FIG. 3 shows a plot of surfactant blend vs. spent acid
volume; and
[0018] FIG. 4 shows a part schematic of a further embodiment of the
invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0019] I--Testing Pumps, Separator, Skimmer & Surge Tank
[0020] To achieve the aims of the invention, it is necessary to
re-inject oil into the production line after spent acid is cleaned
out. In order to achieve this, units for pumping live oil from the
separator or surge tank are necessary to overcome the pressure in
the production line especially at the start of the clean-up
operation. It is also useful to have these pumps in order to
achieve representative data during production well testing where it
is required to have a relatively low separator pressure (to respect
the choke performance /critical flow condition where downstream
pressure should be 50% less than the upstream pressure).
[0021] Traditional three-phase separators work on the principle of
gravity force settling and difference in gravity between the phases
and the retention time of mixture. For oil and water production at
5000 bbls/day retention time in the separator is typically around 2
minutes, which can be less than the precipitation velocity of water
droplets by gravity, which is calculated from the following
formula: 1 V = D 2 ( Sg w - Sg o ) g 18
[0022] Where:
[0023] V=Velocity
[0024] D=Droplet diameter
[0025] Sg.sub.w=Water specific gravity
[0026] Sg.sub.o=Oil specific gravity
[0027] .mu.=Viscosity
[0028] g=gravity force
[0029] This can result in discharging water with high oil content
that could reach more than 2000 ppm, and water with the oil phase
to production facilities. Water quality can be improved after
separation by increasing retention or settling time, using settling
equipment such as skimming units.
[0030] FIG. 1 shows a schematic of a system according to the
invention. Fluids (oil, water, gas) pass from the well head 10 to a
separator 20 where the three phases separate, the gas being passed
to a burner 30 and the oil and water settling in different parts of
the separator 32, 34. The separation time and overflow into the oil
compartment 34 (oil/water interface) are controlled by an automatic
level control system; Water from the bottom of the separator which
is still contaminated with oil is passed 36 to the skimmer 38 where
further separation of oil and water takes place, the water at the
bottom of the skimmer which has reduced oil contamination being
dumped 40. Oil from the separator 20 which still has a significant
amount of water mixed in is diverted 42 to a surge tank 44 (for
example 80 bbl capacity) to allow further separation of dispersed
water or water carryover. Oil from the surge tank 44 passes, via a
pump 46, to the production line 48. The oil from the skimmer 38 is
directed to the surge tank 44 for further separation and
re-injection into the production line 48 while water from the
bottom of the surge tank 44 is directed to the skimmer 38 for
further separation and dumping 40. Thus the skimmer 38 and surge
tank 40 together define a closed system and allow an improvement in
the quality of water dumped, reduced toxic emissions and heat
radiation and increased production/recovery.
[0031] Water is sampled at the separator inlet 54 and outlet 56 and
from the bottom of the surge tank 58 and tested for pH
frequently;
[0032] II--Chemical Treatment
[0033] A. Neutralization Process
[0034] To reduce the oil in water content, it is necessary to clean
the clean up fluids from the first production. The acid in the
clean up fluids is neutralized so that it can go through the
separator from the start. For example, about ten gallons per foot
of 15% HCL can be utilized to stimulate horizontal wells while
higher volumes might be utilized for deviated oil and gas wells.
Even after allowing the acid to soak into formation for 4 hours to
allow proper contact, the pH of spent acid at surface is often in
the range of 2 to 3. To overcome this problem, neutralization
agents are used to raise the pH of the back flowed effluents to
above 5.5. This is the acceptable limit to divert the effluents
through the surface equipment and sea line. Soda ash solution
(Na.sub.2CO.sub.3) is used for the following reasons:
[0035] produces soluble products in water;
[0036] is less toxic than other chemicals;
[0037] cost effective;
[0038] is usually available on the rig site.
[0039] The graph in FIG. 2 shows the relation between
Na.sub.2CO.sub.3 and the amount of acid injected.
[0040] B. Chemicals to Accelerate the Breaking of Emulsions
[0041] A blend of surfactants is used for the purpose of breaking
emulsions present prior neutralizing the produced fluid to avoid
toxicity problems. Tests have revealed the compatibility and
efficacy of blended surfactants at very small dosages in comparison
with individual chemicals. The utilization of blended surfactants
allows the oil concentration in water to be dropped from 5% down to
0.5% of the returned fluid. Consequently, it is possible to
maintain the chemical level discharged to the sea at the
minimum.
[0042] The graph in FIG. 3 shows the relation between the blended
surfactant and the amount of acid injected.
[0043] Surfactant Blend I
[0044] The blended surfactant contains three different surfactants
and it can be adjusted depending on the returned crude oil
properties. The ratio adjustment of different components adds more
flexibility for the blend.
1 Surfactant Blend I Composition Methanol-based cationic and
non-ionic 40% surface active agents Naphtha-based non-ionic
surfactant 30% Water-based surfactant (a) 30%
[0045] Description of the Chemicals:
[0046] Methanol-Based Cationic and Non-Ionic Surface Active
Agents
[0047] This surfactant is strongly attracted to clay and silicate
minerals. A film of surfactant is adsorbed onto the silicate
surface leaving it preferentially oil wet. This reduces the
tendency of clays to swell and become dispersed in the spent acid.
The surface properties of the surfactant aid in removing clay
particles from the interface between spent acid and oil. This helps
prevent those emulsions that would normally be stabilized by clay
dispersion.
2 Information on ingredients: quaternary amine compound 15-40%
methanol 30-60% aromatic alcohol glycol ether 7-13% propan-2-ol
3-7%
[0048] Naphtha-Based Non-Ionic Surfactant
[0049] This surfactant is soluble in water and acid and is
dispersible in oil. Used in acid, the surfactant remains soluble in
the spent-acid solution, thereby enhancing clean up. The surfactant
can also be used in a light oil displacement/flush to minimize
emulsion blockage and assure rapid clean up, it is compatible with
most anionic and cationic surfactants.
3 Information on in- naphthalene 5-10% gredients:
poly(oxy-1,2-ethanediyl)-nonylphenyl- 1-5% hydroxy heavy aromatic
naphtha 60-100%
[0050] Water-Based Surfactant (a)
[0051] This surfactant is a superior surface-active agent for use
in hydrochloric acid (HCl) and mud acid, as well as brine and
water-base fracturing fluids. It contains fluorinated hydrocarbons
and reduces the surface tension of acid solutions to levels
previously unattainable with conventional surfactants. This
lowering of surface tension enables easier acid penetration into
the reservoir porosity. The superior surfactant properties provide
better clean up results.
4 Information on ingre- propan-2-ol 30-60% dients: aliphatic
alcohol glycol ether 10-30% methanol 5% water 30-60% oxyalkylated
alkanols 0-20% quaternary amine iodide derivative 0-1% quaternary
amine chloride derivative 0.1-1%
[0052] Surfactant Blend II
[0053] Depending on the quality of the oil, different blends of
surfactants can be used. When there is a high sludging tendency,
tests reveal that Surfactant Blend I might not be efficient.
Surfactant Blend II can be used in these cases.
5 Surfactant Blend II Composition Dodecylbenzene sulfonic
acid-based non- 30% ionic surfactant (a) Naphtha-based non-ionic
surfactant 30% Water-based surfactant (a) 20% Methanol-based
cationic and non-ionic 20% surface active agents
[0054] Some crude oils react with acid to form a black asphaltic
sludge. This sludge is formed by the coagulation of unstable
colloidal material present in many crude oils. Sludge can stabilize
emulsions, causing plugging of flow channels and pore spaces. It is
sometimes responsible for the poor performance of acid treatments
in some reservoirs. Dodecylbenzene sulfonic acid-based non-ionic
surfactant is used in acid to alleviate crude oil sludging
problems. It is also a good non-emulsifying agent and can often be
used to prevent both sludge and emulsions from forming. It
functions by stabilizing the colloidal material, preventing or
inhibiting the contact of positive ions of acid, iron and calcium
with the colloid.
6 Information on dodecylbenzene sulfonic acid 54% Dodecylbenzene
sul- poly(oxy-1,2-ethanediyl)-nonylphenyl- 10-30% fonic acid-based
non- hydroxy ionic surfactant (a): methanol 24%
[0055] Alternative Products for Use in Surfactant Blends:
[0056] Dodecylbenzene sulfonic acid-based non-ionic surfactant (b)
(replacing Dodecylbenzene sulfonic acid-based non-ionic surfactant
(a))
7 Information on ingredients: dodecylbenzene sulfonic acid 30-60%
propan-2-ol 10-30% glycol 3-7% water 1-5% glycol-ether 7-13%
glycol-ether 10-30%
[0057] Propan-2-ol-based surfactant (repacing naphtha-based
non-ionic surfactant)
8 Information on ingredients: propan-2-ol 15-40% aromatic
hydrocarbon 5-10% oxyalkylated polyol 10-30% alkyl ether phosphate
ester 5-10% oxyalkylated alkanols 5-10% oxyalkylated alkanols 5-10%
resin A 7-13% water 7-13%
[0058] Water-based surfactant (b) (replacing water-based surfactant
(a))
9 Information on ingredients: polyglycol ether 15-25% polyglycol
ether 8-15% propan-2-ol 15-25% 2-butoxyethanol 17-25% water
10-30%
[0059] C. Process Description (see FIG. 1)
[0060] Clean up fluids, diesel spent acid, oil and gas flow through
the flow line 10 to the eruption manifold 12 where the blended
surfactant is injected upstream 14 of the choke manifold 16 to
allow mixing of the fluid.
[0061] Downstream 18 of the choke manifold 16 a diluted solution of
soda ash (Na.sub.2CO.sub.3) is injected to neutralize the spent
acid before entering the three-phase test separator 20.
[0062] Oily water is then routed 36 to the skimmer 38 and oil is
diverted 42 to the surge tank 44.
[0063] The fluid mixed with demulsifier is routed to the surge
tank, which will increase the retention time to allow water to
settle down and segregate.
[0064] Oil is re-injected to production line 48 after having the
right pH value. Gas from separator, surge tank and skimmer is burnt
30.
[0065] III--Use of Multiphase Pumps
[0066] Gas flaring cm be eliminated by the utilization of
multiphase pumps where the gas can flow together with the oil
through the pump impeller without damaging it, thus allowing the
re-injection of the gas.
[0067] In order to measure multiphase flow rates, a multiphase
tester (for example, Schlumberger's PhaseTester Vx) is used, and to
boost the pressure, a multiphase pump (such as those obtainable
from Framo of Bergen, Norway) is used.
[0068] The process is shown in FIG. 4. The input to the separator
120 is substantially as described above in relation to FIG. 1.
However, in this case there are only two outlets. A first outlet
136 which outputs the water phase to a hydrocyclone or centrifuge
oily water cleaning system (not shown). The oil outlet 142 passes
oil and gas via a multiphase measuring system 160 and a multiphase
pump 146 to the production flow line 148.
[0069] A system according to the invention can improve performance
over prior art processes both from an ecological point of viewand
from technical and economical points of view. Field tests have
yielded the following results:
[0070] Oil flaring reduced by 38% by after the one year and by 65%
by the end of the two years, through the utilization of
single-phase oil re-injection pumps.
[0071] Oil flaring reduced to 0% during the operations where pH
neutralization systems are utilized.
[0072] Improved work environment for operating personnel because of
reduced heat emissions and sea pollution.
[0073] Better reservoir characterization through the use of data
with reduced time restriction on operations.
[0074] Improved cash flow: By these methods, hundreds of thousands
of barrels of oil can be re-injected during one year and several
hundred MMSCF of gas flared during the same year. Protection of
production pipelines from corrosion and prevention of leaks.
* * * * *